Utilities are leaving no stone unturned in their search for ways to save electricity. Federal incentives will support new technologies and projects, but can those incentives overcome structural...
AMI/Demand Response: For Real This Time?
Smart metering is coming of age. Is the utility world ready for it?
recently commissioned McKinsey & Co. to develop a model business case for utility decision makers to use as a starting point in their cost-benefit analyses. And in July, the Demand Response and Advanced Metering (DRAM) Coalition hosted a Web-based seminar that examined the business rationale for smart metering. But whether such efforts prove convincing will depend on utilities’ and regulators’ disposition toward the assumptions in the economic calculus.
“If you run the numbers and include things that may not be, strictly speaking, quantifiable, it is generally a positive business case,” says Rick Nicholson, vice president of research for consulting firm IDC Energy Insights in Framingham, Mass, “But there is a lot of uncertainty about how it will get treated by regulators.”
The way regulators add up the costs and provide rate recovery largely will determine how utilities and their shareholders perceive AMI investments. A public utility commission might easily justify rate-basing capital costs for new metering hardware, but less certain is how a utility should bear the costs of retooling its internal processes to pursue the smart-grid vision, as well as marketing the new program and educating customers to ensure maximum benefits continue flowing.
“If the utility’s costs outweigh the benefits, why should they do it?” asks Dean Maschoff, a managing director with Navigant Consulting in Chicago. “That’s where the regulator has to come in—to consider the big picture and find the middle ground with rate recovery that makes sense.”
Both utilities and regulators are uncertain about how AMI costs should be recovered. The California Public Utility Commission (CPUC) recently approved PG&E’s proposal to rate-base $1.4 billion in AMI investment, plus nearly $400 million more in rate recovery for business risk, marketing and other expenses. In Texas, however, TXU told the state PUC that it would prefer AMI costs to be hived off in a separate surcharge. “The costs should not be shifted to base rates,” TXU stated in its response to the PUC’s AMI inquiry. “Having all such costs be recovered through the surcharge will make it easier to track the recovery of advanced metering costs as compared to other metering costs that will still be incurred.”
In the public-policy calculus, regulators also must consider the fairness of allowing utilities to rate-base the costs of programs that will not benefit all stakeholders equally. “They are concerned about the distributional impacts,” Joskow says. “If they make major changes in rate design, how will it affect customers with different levels of consumption and income, and how will it affect various commercial and industrial customers?”
These economic and political dimensions complicate the effort for regulators, and make it difficult for them to confidently define the importance of AMI investments in the broader energy policy context.
“I think regulators have the toughest job in the world,” Hickman says. “As an industry, we have done a pretty poor job of communicating with regulators. We have not given them the information they need to understand how critical of a component this is. AMI is not an end state, but an enabler.”